1. Field of the Invention
The present invention relates to valves used as plugs during completions of wells in oil and gas production. More particularly the present invention relates to an apparatus and method for providing a remotely operable tubing mounted valve used to control the flow of fluids through the tubing in hostile well conditions.
2. Background of the Related Art
When a well is completed, prior to production, a completion string is run into the well. On run in the string must be open to allow fluid to flow up the tubing of the string. In location the tubing must be sealed so that sufficient downhole pressure can be created to set the production packer mounted on the string and together provide a downhole barrier. The barrier thus allows pressure testing to be undertaken prior to the tubing string being opened so that produced oil can flow up the completion string to the surface.
In order to achieve the opening and closing of the tubing bore downhole a plug or valve is used. When a plug is used, the tubing is run into the well bore. The plug is then run in on wireline, slickline or coiled tubing and is set at a position below the production packer. Once the packer is set, a further trip down the well is required to retrieve the plug so that production can begin.
There are a number of disadvantages in using plugs run on wireline and the like. Each run into the well increases the time to achieve completion and is therefore costly. Running plugs can be dangerous during rig up/rig down. Yet further, the costs can soar if the wire breaks in the hole and the plug has to be “fished” out. Additionally some companies run tubing having a plastic coated inner surface.
Such arrangements don't allow wireline plugs to be run as they damage the coating.
Unfortunately in some environments it is more likely that wireline cannot be run as there is no wireline access to the desired location where the plug is to be positioned. This occurs in highly deviated wells or horizontal wells due to the high angle of deviation within the well at the desired position.
In order to overcome these difficulties valves are located at the end of the tubing string. Typically a hydraulically controlled valve is mounted at the end of the tubing with one or more hydraulic control lines arranged on the outer surface of the tubing up to the surface. The hydraulic control lines must pass back to the surface of the well. There are a number of major disadvantages in this arrangement. The first is that the control lines must pass through the production packer. This effectively breaks a seal in the downhole arrangement and is therefore difficult both to engineer and to operate reliably remotely from the surface. A second disadvantage is in arranging the control lines which must pass down the full length of the well. In extended reach wells at great depths, this is costly and it is difficult to reliably control the pressure in the small diameter lines at the excessive depths. Additionally, the incorporation of these control lines with there incumbent connections provide more opportunities for leak paths to exist in the string.
Recently, remotely operable plugs have been used. These are commonly referred to as disappearing plug technology. One such system is the FBIV (Full Bore Isolation Valve) available from Baker Oil Tools, U.S.A. The FBIV is a single action disc-valve which is normally closed. To operate, the FBIV is located at an end of the tubing string with a sliding sleeve multi-cycle tool (MCT) located above. The FBIV is run-in in the closed configuration with the MCT in the open position allowing the tubing string to self-fill via ports in the MCT. At depth, internal tubing pressure is applied to close the MCT so that pressure testing can be achieved. Then by applying a predetermined number of pressure cycles in the string the FBIV is cycled open for production.
An alternative disappearing plug is the ‘Mirage’ system by Halliburton, U.S.A. In this arrangement a plugging material is located at the end of the tubing string with an autofill sub located above it. During run in, the autofill is open allowing the infill of fluids to the tubing string above the plug. At depth, a number of pressure cycles are generated from surface which close the autofill, test the tubing and set the production packer. The Mirage plug is activated by these pressure cycles and dissolves and disintegrates with the last pressure cycle expending the plug to leave an open well bore for non-restricted production through the tubing string.
Unfortunately these prior art disappearing plugs suffer from major limitations. These prior art plugs/valves are all closed at the surface prior to run-in. They are single action, only being able to be opened remotely once. These features provide two distinct disadvantages. As they are closed during run-in, this means filling the tubing as the completion is run in the well becomes problematic and typically requires an addition piece of equipment i.e. the autofill sub or the circulation sub. These tools are unreliable and prone to debris ingress. The autofill sub only allows well fluid to pass in one direction. Therefore in a well kick situation heavier completion fluid cannot easily be circulated into the well to regain control of the well. The circulation sub does allow reverse flow but has a small flow by-pass area making it prone to blocking up with debris. Debris is a common problem downhole, for example, as the tubing is threaded together pipe dope from each connection make up will find its way into the tubing I.D. In the prior art devices, this dope and any well debris will collect on top of the plugging device. This can give problems with debris going into the mechanism and jamming it up and also with pressure transmittal through the debris itself. It is not uncommon for 20-30 ft of debris to build up above these devices.
A second disadvantage is that the majority of these devices operate by opening on a predetermined number of pressure cycles. Often during surface operations pressures may be applied inadvertently to the tubing and it becomes confusing as to whether they constitute a cycle or not, therefore it becomes less clear how many cycles are left to open the plug/valve. Additionally any shock loading during installation of the plug/valve can cause the internal mechanism to incrementally move, thus using up some cycles without knowledge by the operator. In this way, there are a limited number of pressure related functions which can be carried out without the risk of the valve/plug opening. If the pressure test needs to be repeated or the packer needs to be reset, it may be that any further pressure cycles would automatically cause the valve/plug to open and as a result, the tubing string is opened prior to the required testing or packer setting. In such a case the entire tubing string would require to be retrieved and the operation repeated from scratch. To overcome this problem some valves only operate after a large number of pressure cycles, for example ten. However, if only one cycle is required to set the packer, there is excessive time wasted in creating nine further cycles to finally get the valve to open.